1. Field of the Invention
Embodiments of the invention described herein pertain to the field of electric submersible pump assemblies. More particularly, but not by way of limitation, one or more embodiments of the invention enable an apparatus, system and method for pumping gaseous fluid in electric submersible pump down-hole applications.
2. Description of the Related Art
Fluid, such as gas, oil or water, is often located in underground formations. In such situations, the fluid must be pumped to the surface so that it can be collected, separated, refined, distributed and/or sold. Centrifugal pumps are typically used in electric submersible pump applications for lifting well fluid to the surface. Centrifugal pumps impart energy to a fluid by accelerating the fluid through a rotating impeller paired with a stationary diffuser. The rotation confers angular momentum to the fluid passing through the pump. The angular momentum converts kinetic energy into pressure, thereby raising the pressure on the fluid and lifting it to the surface. Multiple stages of impeller and diffuser pairs may be used to further increase the pressure.
Conventional centrifugal pump assemblies are designed to handle fluid consisting mainly of liquids. However well fluid often contains gas in addition to liquid. Currently available submersible pump systems are not appropriate for pumping fluid with a high gas to liquid ratio, also termed a high gas volume fraction (GVF). Particularly, submersible pump systems need to be better suited to manage gas contained in well fluid. When pumping gas laden fluid, the gas may separate from the other fluid due to the pressure differential created when the pump is in operation. The separated gas forms bubbles in the liquid. If there is a sufficiently high GVF, typically around 10% to 15%, the pump may experience a decrease in efficiency and decrease in capacity or head (slipping). If gas continues to accumulate on the suction side of the impeller, gas bubbles may entirely block the passage of other fluid through the impeller. When this occurs the pump is said to be “gas locked” since proper operation of the pump is impeded by the accumulation of gas. As a result, careful attention to gas management in submersible pump systems is needed in order to improve the production of gas laden fluid from subsurface formations.
A typical impeller of a centrifugal pump is shown in FIGS. 1A and 1B. In FIG. 1A, closed impeller 100 is shown with six evenly spaced conventional vanes 105. For illustration purposes only, upper conventional shroud 110 and lower conventional shroud 115 are shown in FIG. 1B, but are not shown in FIG. 1A. FIG. 1B shows a cross sectional view of closed impeller 100 with two conventional shrouds, upper conventional shroud 110 and lower conventional shroud 115. In FIG. 1B, conventional hub 125 is long and hollow and connected to lower conventional shroud 115, upper conventional shroud 110 and conventional vanes 105. Conventional hub 125 slides over conventional shaft 130 and is keyed to conventional shaft 130, which causes closed impeller 100 to rotate with conventional shaft 130. Closed impeller 100 rotates counterclockwise or clockwise with shaft 130. Apertures 120 (shown in FIG. 1A) balance the pressure on each side of closed impeller 100. Conventional closed impeller 100 has a suction specific speed of about 6000.
Closed impeller 100 is paired with a conventional stationary diffuser, such as that shown in FIG. 2, such that each impeller rotates within (inward of) the diffuser to which it is paired. The diffuser does not rotate, but is mounted co-axially with the impeller and nests on the diffuser of the previous stage. Typically there is a clearance gap between the diffuser and impeller to which it is paired. This conventional clearance gap is typically about 0.015 inches to about 0.02 inches in width for conventional semi-open impellers.
Currently, gas separators are sometimes used in pump assemblies in an attempt to address the problems caused by gas in produced fluid. In such instances, a gas separator typically replaces the intake section of a pump assembly in a well containing fluid with a high GVF, with the upstream end of the intake including ports to take in well fluid. Gas separators attempt to remove gas from produced fluid prior to the fluid's entry into the pump section of the assembly. These separators, which also include a rotating shaft through their center, employ the inertia of rotating motion to separate fluid of varying density. There are two main types of gas separators, vortex and rotary. FIGS. 8A and 8B illustrate gas separators of the prior art. FIG. 8A is a rotary gas separator of the prior art. FIG. 8B is a vortex gas separator of the prior art. However it is often infeasible, costly or too time consuming to ascertain the correct type of pump and separator combination which might be effective for a particular well, and even if the correct arrangement is ascertained, the separator may not remove enough gas to prevent a loss in efficiency and/or prevent gas locking.
In the case of an electric submersible pump (ESP), a failure of the pump or any support components in the pump assembly can be catastrophic as it means a delay in well production and having to remove the pump from the well for repairs. A gas separator for a submersible pump assembly capable of reducing bubble size, homogenizing produced gaseous fluid and venting unhomogenized gas would be an advantage in all types of submersible assemblies.
Currently available pump assemblies do not contain components to satisfactorily homogenize gas laden fluid and prevent gas locking. This shortcoming decreases the efficiency and overall effectiveness of the pump assembly. Therefore, there is a need for an apparatus, system and method for pumping gaseous fluid in electric submersible pump applications.